Method and system for purging coil tubing using onsite gas

ABSTRACT

A coil tubing purging system is disclosed having coil tubing; an on-site source of a gaseous hydrocarbon fluid, said gaseous source being coupled to a first end of the coil tubing for injecting the gaseous fluid into the coil tubing for purging; and a sink coupled to a second end of the coil tubing for receiving fluid discharged therefrom.

FIELD OF THE DISCLOSURE

The present invention relates generally to a method and system for purging coil tubing, and in particular, a method and system for purging coil tubing using onsite gaseous sources.

BACKGROUND

Coil tubing purging is known. Normally, coil tubing purging is conducted at the completion of coil tubing operations to purge any remaining liquids from the coil or coiled tubing. It is generally desired to conduct coil tubing purging after nearly every coil tubing job. A typical job for coil tubing includes conveying a mud motor and bit downhole for milling out frac plugs from a well after a fracturing operation. There are numerous reasons for purging the coil tubing including: reducing transport weight, removing caustic liquids that may damage the coil tubing during storage, avoiding cross contamination of liquids from well to well, legal restrictions on transporting dangerous goods, reducing the risk of damaging the coil tubing or creating a hazardous situation on future jobs due to water-based fluids forming ice plugs inside the coil tubing, and adherence to general safe work practices.

Currently, two (2) alternative coil tubing purging solutions are widely used.

The first solution is coil tubing purging with nitrogen, in which nitrogen is used to displace fluid from the coil tubing and in some cases to leave a nitrogen blanket in the coil tubing. Nitrogen is typically hauled, in liquid form, by a large tractor-trailer unit from a refinery or gas processing plant to a wellsite. The liquid nitrogen is pumped by a specialized pumper and then heated to vaporize the nitrogen into a gaseous state before it passes into the coil tubing to purge any liquids from the coil tubing into the wellbore. This requires 2 to 3 operators to operate, and required on a standby basis for 24 hour operations, causing significant labor cost. Hauling the liquid nitrogen to the jobsite, which can sometimes be hundreds of miles, also causes significant shipping burden and expenses.

The second solution is to use a wiper dart followed by compressed air for coil tubing purging in warm climates. A wiper dart or ‘pig’ is used to separate the air from any liquids present in the coil. A large air compressor can be utilized to compress air which in turn can be used to push the wiper dart through the coil tubing. The wiper dart has a ‘squeegee’ effect, i.e., as the wiper dart passes through the coil tubing, it pushes any liquids in the coil out of the distal end of the coil tubing and into the wellbore. The wiper dart also minimizes comingling of the compressed air and any liquid hydrocarbons present in the coil, the combination of which could pose a risk of an explosion. This approach is typically only used with short coil tubing (under 1200 m) with a diameter of approximately 73 mm (2.875″).

While being widely used, the above mentioned solutions have their disadvantages and may not be applicable to every well.

As suggested, there are potential safety concerns with utilizing compressed air, and coil tubing purging using compressed air is only safely possible if no liquid hydrocarbons are present in the coil tubing. Further, air purge is really only consistently successful if the liquids in the coil tubing cannot form ice plugs in the time taken to purge the coil tubing. In cold weather; the compressed air purge may not be fast enough to clear water from the coil tubing before the water freezes. For this reason, coil tubing purging using compressed air is mainly used in warm climates.

Nitrogen has an additional benefit over compressed air in that, in vaporized form, it is generally pumped through the coil at elevated temperatures which can assist in warming up and drying out the coil tubing. However, in many cases, nitrogen is trucked a long distance, and is only used to purge the coil tubing after coil tubing operations are concluded. It is normal to keep the nitrogen unit, a large scale tractor-trailer setup and operator, on standby during the entire coil tubing job. The nitrogen unit is kept on hand in case any unforeseen circumstances prevent the job from continuing and the coil has to be purged before the normal completion of coil tubing operations. Typical costs for the nitrogen purge after each coil tubing milling job are about $5,000 to $10,000.

Both of the above mentioned alternatives require specialized equipment or costly equipment on standby for long periods, resulting in extra cost and dedicated manpower. As economics in shale oil and gas plays get tighter, operators continue to look for ways to reduce costs to get shale wells on production. Considerable savings can result by avoiding the need to maintain a nitrogen unit on stand.

It is therefore an object to provide a novel method and system for purging coil tubing.

SUMMARY

Generally, a method is provided for purging coil tubing using an on-site gaseous source of hydrocarbon fluid. Use of an on-site source results in significant savings. Use of on-site sources include enabling a flow path and management of purged fluids to some end destination or sink.

In one aspect, the method comprises sourcing an on-site gaseous source of hydrocarbon fluid, fluidly coupling a first end of an on-site coil tubing to the on-site source of the on-site fluid and fluidly coupling a second end of the coil tubing to a sink. Through appropriate connections, one enables a flow path for the on-site fluid to flow from the gaseous source through the coil tubing and into the sink and one injects the on-site fluid from the gaseous source along the flow path through the coil tubing into the sink for purging the coil tubing.

In embodiments, the coupling of the first end of the on-site coil tubing to the on-site source of gaseous fluid can comprise establishing a connection to one or more on-site wellheads, one or more on-site subterranean formations of the gaseous fluid, an on-site pipeline, an on-site natural gas plant, or a gasified form of liquefied natural gas. Further coupling of the second end of the coil tubing to a sink can comprises establishing a connection between the second end of the coil tubing and a wellbore, a vessel, a combustor.

In another aspect, the method comprises coupling a first end of the coil tubing to a gaseous source, said gaseous source supplying a gaseous fluid from an on-site downhole environment or a production facility, coupling a second end of the coil tubing to a sink, enabling a flow path for the gaseous fluid to flow from the gaseous source through the coil tubing into the sink; and injecting the gaseous fluid from the gaseous source along the flow path through the coil tubing into the sink for purging the coil tubing.

In another aspect, a coil tubing purging system comprises coil tubing, an on-site gaseous source of a gaseous hydrocarbon fluid, said gaseous source being coupled to a first end of the coil tubing for injecting the gaseous fluid into the coil tubing for purging; and a sink coupled to a second end of the coil tubing for receiving purged fluid discharged therefrom.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A to 1C show a coil tubing reel unit, wherein

FIG. 1A is a simplified perspective view of the coil tubing reel unit,

FIG. 1B is a simplified side view of the coil tubing reel unit, and

FIG. 1C is a simplified front view of the coil tubing reel unit;

FIG. 2 is a side view schematic diagram illustrating a reel, gooseneck and injector rigged up to a wellhead and wellbore for coil tubing operation;

FIG. 3 is a high level schematic diagram showing an arrangement of of the coil tubing purging system;

FIG. 4 is a flowchart showing a process for purging coil tubing;

FIG. 5 is a side view schematic diagram of a coil tubing purging system according to one embodiment using a wellhead source and a pressurized tank receiver or sink;

FIG. 6 is a side view schematic diagram of a coil tubing purging system according to an alternative embodiment using a pipeline source, a compressor and a wellbore as a sink;

FIG. 7 is a side view schematic diagram of a coil tubing purging system for processing natural gas from one well, transport to another site and purging coil tubing on-site for discharge of purged fluid to a P-tank, such as through or bypassing a wellhead;

FIG. 8 is a side view schematic diagram of a coil tubing purging system for purging coil tubing on-site using a gaseous source for flow through the coil tubing and discharge of purged fluid to a P-tank, such as through a wellhead bypass; and

FIG. 9 is a side view schematic diagram of a coil tubing purging system for purging coil tubing on-site using a wellhead structure for managing gaseous fluids from a wellbore, through the coil tubing and back to the wellhead for discharge of purged fluid to a P-tank.

DETAILED DESCRIPTION

The method and system disclosed herein enable safe and cost effective use of compressed gaseous hydrocarbon fluid already found on the wellsite to be utilized to purge the coil tubing, rather than using nitrogen transported to the wellsite or using compressing air. In embodiments, the gaseous hydrocarbon fluid may be sweet natural gas sourced from a well, nearby pipeline or gas processing facility.

In some alternative embodiments, propane may also be used for purging the coil tubing as propane may also already be on-site from frac operations or other well servicing.

In some other embodiments, gaseous fluid produced from liquefied natural gas (LNG), may be used as the gaseous hydrocarbon fluid for purging the coil tubing. Natural gas may be produced from a wellbore, perhaps on-site, and transported to natural gas processing facility via pipeline. In the natural gas processing facility, natural gas is liquefied by using liquefaction compressor(s). LNG may be on the wellsite for fueling equipment such as frac pumps, coil tubing units, or other equipment used in wellsite operations. The LNG could be manufactured onsite, transported via pipeline, or trucked from a nearby natural gas compression facility. Decompression or a heat exchanger is used to gasify the LNG for use.

Shale gas wells, having high shut in pressure can provide as source of purge gas. In North America and parts of the former Soviet Union, milling hydraulic fracturing completions in shale gas wells constitutes a large percentage of coil tubing intervention work. In 2013 over 80% of all coil tubing work in North America involved milling frac plugs and valves. Shale wells have a high shut in pressure after frac plugs are milled typically ranging from 8 MPa (1160 psi) to 60 MPa (8700 psi) in extreme cases. Typical shut in pressures are in the 20 MPa (2900 psi) range. All of these pressures are sufficient to purge coil tubing.

Turning now to FIGS. 1A to 1C, a coil tubing reel unit is shown and is generally identified using numeral 100. In this embodiment, the coil tubing reel unit 100 comprises a skid or trailer 102 for transport of a reel of coil tubing. A tubing reel 104, having coil tubing 106 wrapped thereon, and a control unit 105 are mounted on the trailer 102. The tubing reel 104 comprises a coil tubing rotating joint 108 for the swivel connection to non-rotating fluid lines 110. The fluid lines 110 adjacent the rotating joint 108 include a valve 112 for flow control. The reel of coil tubing 106 includes a whip end leaving the reel 104 for conveyance to a wellhead and running downhole. The coil tubing 106 is managed, in a conventional manner, on and off the reel 104 using a level wind 114 and monitored with a depth counter 116. The tubing reel 104 is driven by a reel drive motor 118 via a drive chain 120. A reel brake 122 is coupled to the reel for stopping the reel 104 as required.

With reference to FIG. 2, in a coil tubing operation, the whip end of the coil tubing 106 is guided to enter a wellbore 142 through a wellhead 144 thereon. Various downhole equipment 146, e.g., a bottom hole assembly (BHA), may be coupled to the coil tubing 106 for working downhole, the detail of which is well known in the art, and is omitted herein. After the coil tubing operation, or in cases that the coil tubing operation has to be terminated, coil tubing purging may be conducted using the system and method described below.

FIG. 3 is a high level schematic diagram showing the structure of the coil tubing purging system 200. As shown, the system 200 comprises an on-site gaseous source 202 suitable for providing a gaseous fluid for purging the coil tubing 106. The gaseous source 202 is coupled to one or more gaseous fluid handling equipment 204, which are in turn coupled to one of the reel end or the whip end of the coil tubing 106 and transports the gaseous fluid into the coil tubing for purging operation. The other end of the coil tubing 106 is coupled to a sink 206 for discharging the purged gaseous fluid, liquid and debris (if any) from the coil tubing 106 thereinto. As will be described in more detail below, the gaseous fluid handling equipment 204 is optional, and may not be required in some embodiments. Moreover, although not shown in FIG. 3, the system may also comprise other components, e.g., suitable conduits for transporting the gaseous fluid.

Various embodiments are readily available by selecting suitable on-site gaseous source 202, gaseous fluid handling equipment 204 and the sink 206, which are described below in great detail. Those skilled in the art understand that the various types of on-site gaseous sources 202, gaseous fluid handling equipment 204 and the sink 206 described herein may be combined as needed to form the coil tubing system.

On-Site Gaseous Source

In some embodiments, the on-site gaseous source 202 is suitable for providing an on-site gaseous fluid. The gaseous fluid may be an inexpensive hydrocarbon fluid such as natural gas/methane, coal bed methane, gasified liquefied natural gas (LNG), propane, synthesis gas (or “syngas” produced from, e.g., in-situ combustion of “green” heavy oil), or other suitable gas. The gaseous fluid may be supplied from a downhole environment or alternatively from a production facility such as a refinery facility. When an LNG source is used, the gaseous handling equipment 204 may comprise a gasifying device for gasifying the LNG for purging the coil tubing 106.

In one embodiment, the one-site gaseous source comprises one or more wellbores 142, such as one or more natural gas wells, having suitable components such as the wellhead, downhole casing and the like, and suitable for generating gaseous fluid. In some alternative embodiments, the on-site gaseous source is a pipeline transporting gaseous fluid to, or passing by, the jobsite. The jobsite may be the site at which the coil tubing is to be purged, or from one or more wells or one or more production facilities, which may be wells or facilities local to the jobsite, remote thereto or a mixture thereof.

In some other embodiments, the on-site gaseous source may be pressurized containers containing inexpensive hydrocarbon fluid in gaseous or liquid form.

Gaseous Fluid Handling Equipment

The gaseous fluid handling equipment 204 in this embodiment comprises at least the conduits for transporting gaseous fluid from the wellbore 142 into the coil tubing 106.

As raw gas produced from a well often comprises corrosive components, e.g., H₂S, the gaseous fluid handling equipment 204 may also comprise gas treatment processes or system as required to remove the corrosive components and generate treated, “sweet” gas for coil tubing purging.

In situations where the on-site wells generate “sweet” gaseous fluid, the gas treatment devices, such as purifying gas treatment devices, may not be required.

Using “sweet” gaseous fluid produced from one or more wells provides certain advantages for coil tubing purging. For example, most shale gas wells are on multi well pads, offering a source of treated, sweet natural gas. An on-site source of such sweet natural gas can obviate the need for remote and expensive sources of purge gases. As pressurized, “sweet” natural gas are often abundant at wellsites where coil tubing is typically utilized, using “sweet” natural gas for purging the coil tubing of liquids at the conclusion of the job enjoys an advantage of lower cost compared to coil tubing purging using nitrogen.

The gaseous fluid handling equipment 204 may also comprise other components. For example, the gaseous fluid handling equipment 204 may comprise a gas scrubber for removing liquid droplets from the gaseous fluid streams. In situations where the pressure of the gaseous fluid is insufficient for purging the coil tubing, for example, for discharge to a higher pressure sink 206, to the gaseous fluid handling equipment 204 may further comprise a compressor for supplying gaseous fluid at a higher pressure, sufficient for coil tubing purging.

Sink

The sink 206 collects purged gaseous fluid. The collected gaseous fluid may be stored, combusted, transported to other sites via pipeline or vehicle transportation, or locally processed, depending on the implementation.

The sink 206 is a device suitable for the safe receipt of the purged gaseous fluid discharged from the purged coil tubing. For example, the sink 206 may be a pressurized tank (P-Tank), pipeline, riser, pig launcher, separator, compressor station, oil battery, rig tank, or other suitable vessel or midstream facility for collecting the discharged gaseous fluid. While less than ideal, applicant is aware that natural gas has even been directed to open tanks such as rig tanks, typically having baffles therein to prevent fluid slugs from splashing out of the tank.

When a P-Tank is used as the sink 206, it may further discharge the gaseous fluid received therein to a pipeline for transporting to other sites.

The sink 206 may alternatively be some other form of flowback facility to allow for the safe discharge of hydrocarbons including combustors, e.g., a flare stack, capable of burning the gaseous hydrocarbon fluid discharged from the coil tubing 106. In many embodiments, the flare stack is used with a vessel such as a P-Tank as described above such that the purged gaseous fluid is first discharged into the P-Tank, and the P-Tank discharges the gaseous fluid to the flare stack for burning. In some embodiments, the purged gaseous fluid may be directly discharged from the coil tubing into a suitable combustor. The vessel can also be used to separate liquids from gaseous hydrocarbons.

In situations that cross-contamination is not a risk or consideration, the sink 206 may be a wellbore. Typically in milling jobs, water is utilized as the power fluid and thus the introduction of with flammable natural gas is safe as the coil tubing bore is absent air or oxygen. In some embodiments, the wellbore used as the sink is a wellbore different to that used as the gaseous source. In some alternative embodiments, the wellbore used as the sink may be a wellbore also used as the gaseous source.

Although not shown in FIG. 3, the coil tubing 106 may be coupled to the sink 206, typically the wellhead via a blowout preventer (BOP) and flow tee.

Coil Tubing Purging Process

FIG. 4 is a flowchart showing a process 300 of purging a coil tubing. As described before, the process 300 starts (step 302) when the coil tubing operation is completed or terminated. After start, the coil tubing 106 is coupled to the gaseous source via the gaseous fluid handling equipment 204 if they are not yet coupled (step 304), and the coil tubing 106 is coupled to the sink 206 if they are not yet coupled (step 306). As described above, if gaseous handling equipment 204 is used, and the coil tubing 106 is coupled to the gaseous source 202 via the gaseous handling equipment 204. As understood by the on-site operators, various control valves are provided for controlling the flow of purge gas through the coil tubing. Control is typically provided by manipulating a valve at the inlet to the coil tubing. Thus, for fluid flow from the reel end to the whip end, a valve at the reel end is appropriate and vice versa.

The gaseous source 202 and the coil tubing 106 are prepared to enable a flow path for the gaseous fluid to flow from the gaseous source 202 to the coil tubing 106 for purging (step 308). The source, coil tubing and sink are all fluidly connected to form the flow path. The coil tubing purging is then conducted by injecting gaseous fluid from the on-site gaseous source 202 along the flow path into the coil tubing 106, which pushes any liquid in the coil tubing 106 out and is discharged into the sink 206 (step 310). The process 300 terminates after the coil tubing is purged (step 312).

Examples

FIG. 5 shows an example of the coil tubing purging system according to one embodiment. In this embodiment, the on-site gaseous source is a natural gas wellbore 142 generating “sweet” natural gas, and the sink is a P-Tank 342. No gaseous fluid handling equipment is used in this embodiment. In this embodiment, the downhole coil tubing check valve at about the BHA 146 can be disabled and the coil tubing 106 can be purged using sweet gas from the wellhead 144.

Following the process 300 of FIG. 4, the coil tubing purging is started (step 302) after performing coil tubing intervention work that may include milling frac plugs, ball seats, or other completion equipment.

In one embodiment, as the whip end coil tubing 106 is already coupled to the gaseous source, step 304 is nominal. The reel end of the coil tubing 106 is fluidly connected to the P-Tank (step 306). Then, the gas well 142 and coil tubing 106 are prepared by making pipe connections and adjusting valving, to enable a flow path for the gaseous fluid to flow back from the wellbore 142 to the coil tubing 106 for purging (step 308). A first end of the on-site coil tubing, in this case the whip end, is fluidly coupled to the on-site source of the on-site fluid. A second end, in this case the reel end, is fluidly coupled to the sink.

In particular, the coil tubing 106 can be pulled to surface for removing the BHA 146, including any check valves from the bottom of the coil tubing 106. Then, the coil tubing 106 is re-connected to the wellbore 142 through the lubricator back onto the wellhead and pressure tested as required. The wellhead can then be opened to deliver wellbore hydrocarbon fluid to the coil tubing 106.

Alternatively, the gas well 142 and coil tubing 106 may be prepared by remotely opening a downhole check valve using electronics, ball drop or other means to allow flow into the coil tubing from the downhole whip end thereof.

After the whip end of the coil tubing is readied to receive hydrocarbon purge fluids, the valving at the reel end of the coil tubing 106 is opened to allow natural gas from the well 142 to flow along the flow path into the coil tubing 106 back to the reel and discharge into the P-Tank 342 to purge the coil tubing 106. During coil tubing purging, flow rate of the natural gas can be regulated by a choke valve 340 located on the discharge side between the coil tubing 106 and the P-Tank. The coil tubing purging is completed (step 312) when no further liquid ‘slugs’ are discharged from the coil tubing 106, at which time the choke valve 340, reel valve 112, wellhead 142 or other block valve along the flow path is closed and the coil tubing is rigged out. In this embodiment, the coil tubing purging operation must be conducted carefully as there can be safety issues associated therewith in some situations as it removes the secondary containment conventionally provided by the safety valve in the BHA.

FIG. 6 shows an example of the coil tubing purging system according to an alternative embodiment. In this embodiment, the on-site gaseous source is a natural gas pipeline 362 carrying “sweet” natural gas. The pipeline 362 is fluidly connected via a choke valve 360 to the gaseous fluid handling equipment 204, which is a compressor 364 in this embodiment, and the compressor 364 is fluidly connected to the reel end of the coil tubing 106. In this case the reel end is a first end connected to the gaseous source. The second or whip end of the coil tubing 106 is deployed in a wellbore 142, which acts as the sink 206.

As shown, purge gas from the pipeline 362 is introduced at the rotating joint 108 of the reel 104 for transport through the coil tubing 106 from the reel end to the whip end thereof. The whip end of the coil tubing 106 is located in the wellbore 142 for discharging fluid thereinto. In this example, the pipeline pressure P_(p) is less than or about the same as the well pressures P_(w), and thus the compressor 364 is employed for boosting the pipeline pressure for injecting natural gas into the coil tubing with sufficient pressure for purging. Alternately, the whip end of the coil tubing can be fluidly connected or secured directly to a sink or receiver such as the P-tank through a wellhead bypass, avoiding discharge of purged fluid to the wellbore.

FIG. 7 shows an example of the coil tubing purging system according to another embodiment. In this embodiment, the on-site gaseous source is a natural gas pipeline 362 carrying “sweet” natural gas produced from a well 142A. As shown, the natural gas produced from the well 142A is transported to a processing facility 370 for generating “sweet” natural gas, which is transported to the jobsite via the pipeline 362 for using as purge gas.

The pipeline 362 is fluidly connected via a choke valve 360 to a compressor 364, and the compressor 364 is fluidly connected to the reel end of the coil tubing 106. The whip end of the coil tubing 106 is deployed in a wellbore 142B through a wellhead 144. The wellbore 142B is also fluidly connected to a P-Tank 342 via conduits 372.

The compressor 364 pressurizes the natural gas from the pipeline 362 to a pressure higher than that in the wellbore 142, and introduces the pressurized natural gas into the coil tubing 106 for purging. The purged fluid is discharged from the whip end of the coil tubing 106 into the wellbore 142B, and eventually flows into the P-Tank 342 via conduits 372 for storage. As described before, the purged fluid in the P-Tank 342 may be stored, further processed, burned or transported to other sites.

FIG. 8 shows an example of the coil tubing purging system according to yet another embodiment. In this embodiment, an on-site gaseous source 362 supplying gaseous fluid is fluidly connected to the reel end of the coil tubing 106. The coil tubing 106 is pulled to the surface with the whip end thereof in the lubricator 374 and the end of the BHA in the wellhead 144 of a well 142. The wellhead 144 is fluidly connected to a P-Tank 342 via conduits 372.

To purge the coil tubing 106, the wellhead 144 is closed by a suitable valve or blind ram 376. Then, a flow path is established from the gas source 362 through the coil tubing 106 to the P-Tank 342 such that gaseous fluid flows from the gas source 362 into the coil tubing 106 for purging it. The purged fluid is discharged from the coil tubing 106, bypassing the well head 144, into the P-Tank 342 via conduits 372. As described before, the purged fluid in the P-Tank 342 may be stored, further processed, burned or transported to other sites.

FIG. 9 shows an example of the coil tubing purging system according to still another embodiment. In this embodiment, a wellbore 142 is used as the on-site gaseous source for supplying gaseous fluid. The coil tubing 106 is pulled to the surface with the BHA remaining sealed in the lubricator 374 atop the wellhead 144 of the wellbore 142. The wellhead 144 is closed by a suitable wellhead valve 376, such as a blind ram of a BOP. The wellhead 144 comprises a first flow tee 382 below the wellhead valve 376. The first end or reel end of the coil tubing 106 is fluidly connected to a wellbore side of the first flow tee 382. The wellhead has a wellhead valve 376 isolating the first flow tee from a second flow tee 384. The second flow tee 384 is above the wellhead valve 376, and is fluidly connected to a P-Tank 342. The system also comprises flow control and safety means such as additional valves and BOP as required. The wellhead is used to manage the fluid flow from the wellbore, to the coil tubing 106, and discharged to the sink.

To purge the coil tubing 106, a flow path is established from the wellbore 142 via the first flow tee 382 to the coil tubing 106, and then via the second flow tee 384 to the P-Tank 342, such that gaseous fluid flows from the wellbore 142 via the first flow tee 382 into the coil tubing 106 for purging it. The purged fluid is discharged from the coil tubing 106, via the second flow tee 384, into the P-Tank 342. As described before, the purged fluid in the P-Tank 342 may be stored, further processed, burned or transported to other sites.

In above embodiments, the coil tubing 106 is described as being supported in a reel mounted on a tractor-trailer unit. Those skilled in the art appreciate that the coil tubing 106 in some other embodiment may be held in other supporting structure suitable for deployment, including skids and self-propelled platform.

In an alternative embodiment where the coil tubing is made of or otherwise coated with a material resistant to corrosion, a gaseous fluid containing corrosive components may be used for purging, and thus no gaseous fluid treatment device would be required.

While less likely, in situations where corrosion of the coil tubing is not a risk or a consideration, the gaseous fluid containing corrosive components may be used for purging, and thus no gaseous fluid treatment device is used in the system. In one embodiment, an inhibitor slug can first be pumped into a wellbore, and the gaseous fluid generated from the wellbore after the inhibitor is pumped in may be directly used as the gaseous fluid for purging the coil tubing without being treated by a gaseous fluid treatment device.

Those skilled in the art appreciate that flow control would be implemented in above embodiments. Preferably, flow control valve(s) may be deployed near the gas source, and flow meter(s) may be deployed near the sink.

Although embodiments have been described above with reference to the accompanying drawings, those of skill in the art will appreciate that variations and modifications may be made without departing from the scope thereof as defined by the appended claims. 

1. A method for purging a coil tubing comprising: sourcing an on-site gaseous source of hydrocarbon fluid; fluidly coupling a first end of an on-site coil tubing to the on-site source of the on-site fluid; fluidly coupling a second end of the coil tubing to a sink; enabling a flow path for the on-site fluid to flow from the gaseous source through the coil tubing and into the sink; and injecting the on-site fluid from the gaseous source along the flow path through the coil tubing into the sink for purging the coil tubing.
 2. The method of claim 1 wherein the coupling of the first end of the on-site coil tubing to the on-site source of gaseous fluid comprises establishing a connection to one or more on-site wellheads, one or more on-site subterranean formations of the gaseous fluid, an on-site pipeline, or an on-site natural gas plant.
 3. The method of claim 1 wherein the coupling of the first end of the on-site coil tubing to the on-site source of gaseous fluid comprises establishing a connection to an on-site container of the gaseous hydrocarbon fluid.
 4. The method of claim 1 wherein said gaseous fluid is natural gas, liquefied natural gas, coal bed methane, shale gas, propane or synthesis gas.
 5. The method of claim 1 wherein coupling of the second end of the coil tubing to the sink comprises establishing a connection between the second end of the coil tubing and a wellbore or a vessel.
 6. The method of claim 1 wherein coupling of the second end of the coil tubing to the sink comprises establishing a connection between the second end of the coil tubing and a combustor for burning the received gaseous fluid.
 7. The method of claim 1 wherein said coupling of the first end of the coil tubing to a gaseous source comprises coupling the gaseous source to a gaseous fluid handling equipment, and coupling the gaseous fluid handling equipment to the first end of the coil tubing.
 8. The method of claim 1 wherein said coupling a first end of the coil tubing to a gaseous source comprises establishing a connection: between the gaseous source and an on-site gaseous fluid treatment device for removing corrosive components from the gaseous fluid, and between the gaseous fluid treatment device and the first end of the coil tubing.
 9. The method of claim 1 wherein said coupling a first end of the coil tubing to a gaseous source comprises establishing a connection: between the gaseous source and an on-site compressor, and between the compressor and the first end of the coil tubing.
 10. The method of claim 1 wherein coupling a second end of the coil tubing to a sink comprises establishing a connection: between the second end of the coil tubing and a blowout preventer at an on-site wellhead, and between the blowout preventer and the sink.
 11. A method for purging a coil tubing comprising: coupling a first end of the coil tubing to a gaseous source, said gaseous source supplying a gaseous fluid from an on-site downhole environment or a production facility; coupling a second end of the coil tubing to a sink; enabling a flow path for the gaseous fluid to flow from the gaseous source through the coil tubing into the sink; and injecting the gaseous fluid from the gaseous source along the flow path through the coil tubing into the sink for purging the coil tubing.
 12. A coil tubing purging system comprising: a coil tubing; an on-site gaseous source of a gaseous hydrocarbon fluid, said gaseous source being coupled to a first end of the coil tubing for injecting the gaseous fluid into the coil tubing for purging; and a sink coupled to a second end of the coil tubing for receiving purged fluid discharged therefrom.
 13. The system of claim 12 wherein said gaseous source is a container containing the gaseous hydrocarbon fluid.
 14. The system of claim 12 wherein said sink is a wellbore.
 15. The system of claim 12 wherein said sink is a vessel.
 16. The system of claim 12 wherein said sink is a combustor for burning the received gaseous hydrocarbon fluid.
 17. The system of claim 12 further comprising gaseous fluid handling equipment, said gaseous source being coupled to the coil tubing via the gaseous fluid handling equipment.
 18. The system of claim 17 wherein said gaseous fluid handling equipment is a gaseous fluid treatment device for removing corrosive components from the gaseous fluid.
 19. The system of claim 17 wherein said gaseous fluid handling equipment is a compressor located between the gaseous source and the coil tubing.
 20. The system of claim 19 wherein said gaseous source is an on-site pipeline transporting the gaseous hydrocarbon fluid and the sink is an on-site wellbore.
 21. The system of claim 12 wherein said coil tubing is coupled to the sink via a blowout preventer at an on-site wellhead.
 22. The system of claim 21 wherein the first end of the coil tubing is connected to a wellbore side of a first flow tee at an on-site wellhead; the wellhead has a wellhead valve isolating the first flow tee from a second flow tee; and the second flow tee is connected to the sink.
 23. The system of claim 12 wherein said gaseous fluid is natural gas, liquefied natural gas, or propane.
 24. The system of claim 12 wherein said gaseous source is one or more wellbores supplying the gaseous hydrocarbon fluid. 